The development of low quality and sour gas reservoirs in recent years has required the development of new techniques for low quality gas handling. In addition, production of oil and gas by CO.sub.2 miscible flooding for enhanced oil recovery can result in sour and low quality gas streams to be processed. A sour natural gas is a natural gas which contains, in addition to hydrocarbon components, one or more acid gas components. An acid gas component, for example, hydrogen sulfide (H.sub.2 S) or carbon dioxide (CO.sub.2), forms an acidic aqueous solution. Gas sweetening involves almost complete removal of H.sub.2 S and most of the CO.sub.2 from sour natural gases. The sweetening is almost always required before the gas can meet sales gas specifications and before the sweet gas can be processed for production of ethane, propane, butane, and higher hydrocarbon liquid products.
The sour gases encountered today may contain in addition to H.sub.2 S and CO.sub.2, carbonyl sulfide, carbon disulfide, methyl through butyl mercaptans, and other volatile sulfur compounds. Almost complete removal of H.sub.2 S and other volatile sulfur compounds is required to meet rigid sales gas specifications. CO.sub.2 removal may be required, for example, to increase the heating value of the residue sales gas, prevent CO.sub.2 frost formation during cryogenic processing, and the like.
FIG. 1, labeled "Block Diagram of Sour Gas Processing Plant--Background," illustrates the background of the invention in greater detail. A wellstream 11 from a sour gas reservoir is flash separated 12 into a gaseous stream 13 and a liquid stream 14. The liquid stream 14 is stabilized 16 to lower the vapor pressure of the liquid stream, thereby producing a stabilized condensate stream 17 and a vapor fraction stream 15 which is typically combined with gaseous stream 13 for gas treatment 18. Gas treatment 18 for a stream from a typical sour gas reservoir separates an acid gas stream 19 containing predominantly H.sub.2 S and CO.sub.2 which can be further processed in a sulfur plant 20 to produce an elemental sulfur product stream 21. Gas treatment 18 also typically produces a sweet gas stream 22 which after dehydration and recovery 23 produces a sweet residue gas stream 24, a liquefied petroleum gas (LPG) stream 25, and a natural gasoline liquids (NGL) stream 26. Dotted line 27 indicates generally the functional locus of the invention herein described in detail below.
In addition to the routine production of low quality and sour natural gas reservoirs, in recent years reduced petroleum reserves have resulted in development of enhanced oil recovery techniques, such as CO.sub.2 miscible flooding, which can result in production of gas streams having a high acid gas content. In the application of CO.sub.2 miscible flooding for enhanced oil recovery, the CO.sub.2 content of the produced gas increases greatly, after breakthrough, even to levels as high as 98 mol% or higher. The modification of sour gas treating facilities to process such high, and, in the case of CO.sub.2 miscible flooding, variable CO.sub.2 loading represents a formidable engineering task.
At low CO.sub.2 levels, established technology is and remains attractive; however, at higher levels, new processes are required. Thus, for example, the MEA (monoethanolamine) and DEA (diethanolamine) processes applied to the gaseous stream are economically attractive at CO.sub.2 levels up to, for example, 30 mol% to 40 mol%. At higher CO.sub.2 levels, due in part to high energy requirements for regenerating the rich MEA or DEA, other processes become desirable. The invention hereinbelow described is useful for processing high acid gas content natural gas streams and also is adapted for use where the composition of the gas stream, for example, a gas stream derived from a production stream from a reservoir undergoing CO.sub.2 miscible flooding, is highly variable as hereinbelow described in greater detail.